This Background section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This background discussion is provided merely to facilitate a better understanding of the present disclosure as it relates to needs of the prior art. Accordingly, it should be understood that this section should be read in this light and not necessarily as admissions of prior art.
Hydrocarbon wells generally include a wellbore that extends from a surface region and/or that extends within a subterranean formation that includes a reservoir fluid, such as liquid and/or gaseous hydrocarbons. After wellbores are drilled, they are typically cased and then perforated or otherwise provided with an aperture or opening at the hydrocarbon-bearing formation intervals to facilitate fluid flow between the wellbore and formation. After perforating, it's often desirable to stimulate or “treat” the subterranean formation to provide improved flow paths for movement of the hydrocarbons from the reservoir rock to the wellbore. The steps of casing the wellbore with an appropriate tubular configuration, perforating the wellbore, and treating the formation to make it productive are collectively, commonly referred to as “completing” the well.
The perforation apertures may be created by various means, such as by using shaped-charge jet perforating of the casing or providing pre-positioned selectively operable orifices or devices, such as with sliding sleeves, rupturable disks, check valves, and removable port covers. Perforation apertures in the wellbore tubulars may be created (i) in-situ using shaped charges fired from a perforating gun, or (ii) pre-installed or pre-drilled apertures such as orifice devices, sliding sleeves, rupture disks, valves, etc.
Traditional in-situ “perforating” using shaped-charge explosives within a perforating gun is the most common method for creating perforations and is typically done after the wellbore tubular (e.g., casing or liner) is positioned into the wellbore. This is traditionally and typically done using electric wireline or coil tubing for deployment of the perforating guns and making a firing location determination from measuring equipment outputs or readouts located at the surface. Actuation signals to the downhole tool, such as to fire perforating guns or actuate the tool, are traditionally provided or communicated to the tool from the surface.
Technical developments over recent years have enabled deployment of “autonomous” or “smart” tool systems that activate independently from surface control or instruction, relying instead upon on-board programming and sensing to perform an operation. Autonomous tools are provided with on-board controllers and processing capabilities to self-determine from a combination of information collected in-transit within the wellbore and instructions programmed into memory when to actuate a tool or “fire” the perforating charges. Autonomous perforating systems may be deployed on a slick-line (non-electrical wireline), free-fall, self-propelling, and/or pumped along the wellbore.
As discussed above in regard to perforating, over the past decade wellbore completion tools have been developed having on-board controller and location devices that are capable of deployment within a wellbore with on-board (“smart”) ability to self-determine the tool's location and to actuate or self-execute a desired function or set of instructions when the tool reaches a determined location or a set of prescribed conditions is met. For example the tools may include a perforating gun fires and perforates the casing when the tool reaches the desired position in the wellbore. Such tools may sometimes be free from tethering from the surface or may be deployed tethered to a wire such as a slick line or coil tubing.
Perforation apertures in the wellbore tubulars may be created (i) in-situ using shaped charges fired from a perforating gun, or (ii) pre-installed or pre-drilled apertures such as orifice devices, sliding sleeves, rupture disks, valves, etc. For purposes herein, apertures created by either method are included as perforations or perforations.
Other autonomous tool developments have included setting bridge plugs, whipstocks, cutting tools, conveying a liquid or even conveying perforating balls within a transport member. At the desired wellbore position, the tool may self-activate to release a liquid or adaptable perforation sealing devices from the transport member or set a conveyed downhole tool.
In autonomous tool operations, the conveyed autonomous tool assembly may be retrieved after use, partially destroyed and partially retrieved, or fully destructed such that no retrieval operation is needed. Fully destructible autonomous tool operations provide the benefit of obviating the need for surface location equipment such as wireline trucks, cranes, and long tool lubricators on wellheads. Fully destructible operations also obviate the need to recover the “brain” or any other measuring or otherwise conveying equipment from within the wellbore, thus saving several days of rig and completion time over the course of a multizone completion operation. Obviating the need to drill out or mill up traditional or autonomously set plugs also greatly reduces the amount of job complexity and risk, completion time, water used, formation damage risks.
The formation may be stimulated by pumping a stimulation fluid through the tubular apertures and into the subterranean formation, such as by pumping an acid into a carbonate type of subterranean formation to etch or dissolve a flow channel through at least a portion of the subterranean formation. Other types of stimulation may include hydraulically fracturing the subterranean formation, such as by supplying a fluid-based fracturing fluid and proppant into a hydraulically induced fracture network.
The completions section of wellbores in both conventional and unconventional reservoirs are generally increasing in length. Whether such wellbores are vertical or horizontal, such wells frequently require the sequential placement of multiple perforation sets and multiple fractures. Each act of perforating and then stimulating is sometimes referred to as a stage. Groups of stages may be performed sequentially, utilizing only perforation sealers isolating the stages. Wellbore plugs are commonly utilized to isolate groups of stages, as convenient or appropriate.
The more the number of completion zones, the more equipment is traditionally required to be included or introduced into the wellbore, and frequently removed therefrom after all zones are completed, such as by drill-out. Use of downhole hardware such as using multiple conventional perforating guns, multiple plugs, etc., increases the time, expense, complexity, and risk of such multi-zone completions. Commonly, the axial length of the hydrocarbon-bearing portion of the subterranean formation encountered by the wellbore requiring completion exceeds the amount of formation that can be effectively stimulated in a single stimulation treatment. Some typical wells may have, for example seventy stages separate into seven groups with six wellbore plugs. More recently, wells are being completed through a producing formation horizontally, with the horizontal portion often extending 5,000 and even 10,000 axial feet through the producing formation. Such completions require performing multiple “stages” or separate completion (perforation and stimulation) treatments to effectively stimulate the totality of hydrocarbon-bearing formation encountered by the wellbore. When multiple stages are required, each stage must be hydraulically isolated from the previous stages to enable the current stimulation treatment fluid to flow into the desired perforations. When one stage is fully treated, it must then be hydraulically isolated from the forthcoming perforation interval and stimulation treatments. In addition to the ball sealers used for hydraulic diversion as discussed above, hydraulic isolation between previously stimulated zones and zones not yet stimulated also may be facilitated using other diversion agents or methods, such as bridge plugs, frac plugs, frac balls, manipulable sleeves, valves, plugging-particulates or flakes, and/or limited entry-perforating. Other exemplary diversion methods are described more fully in U.S. Pat. No. 6,394,184 entitled “Method and Apparatus for Stimulation of Multiple Formation Intervals.”
Spherical ball sealers are commonly used for stimulation fluid diversion and are typically a rubber or polymeric ball that's sized slightly larger than the wellbore perforation so as to seat on the perforation. Ball sealers are selectively introduced into the wellbore with the flowing stimulation fluid stream and transported down the wellbore with the stimulation fluid to the perforations. The ball sealers are intended to seat on the perforations, restricting fluid flow into the formation, causing hydraulic pressure to increase within the wellbore and fracture open the formation behind other perforations that had not previously taken stimulation fluid. For desired effectiveness, perforations are intended to be substantially circular in shape and small enough in diameter after receiving stimulation fluid and proppant for the ball to fully seat on, conform, and hydraulically seal the entire perimeter of the perforation shoulder.
However, traditional ball sealers do not always seat as intended and when seated, often do not affect the desired hydraulic seal. One disadvantage of traditional spherical ball sealers is that often perforations that have taken a lot of stimulation fluid and proppant may be severely eroded to a larger diameter or otherwise have a non-circular perimeter. As a result, a ball sealer engaged thereon cannot effect a perfect hydraulic seal. Some perforations may present burrs or a split shape, also resulting in a non-circular or an irregular perforation shoulder. If a ball does seat, there may be some reduction in flow rate through the perforation, but the needed pressure drop from the seating may not occur. Also, ball sealers may become unseated if insufficient hydraulic pressure differential occurs between the wellbore. Also, some perforations may be bypassed altogether by the balls, leaving them open and receiving a full flow of stimulation fluid during subsequent stages.
Improved perforation sealers comprising a spherical core having a plurality of freely moving arms or tentacles extending from the outer surface of the sealer are also recently known. The spherical core portion of such sealers engages the perforation perimeter similar to how a traditional ball sealer seats on a perforation. Often this still may result in an imperfect hydraulic seal on the perforation seat as discussed above, having leakage pathways along the perimeter therewith. The freely moving arms or tentacles however, are intended to flow with fluid movement into the leakage pathways with the seat, thereby further plugging at least an additional portion of the leakage pathway, further reducing the fluid flow leaking through the seat seal. To avoid potential entanglement of the tentacles with each other within the wellbore or snagging on features within the wellbore, the sealers are provided with a removable shell or related temporary confinement feature for the tentacles.
Another useful multiple-zone completion technology relates to autonomously deployable tools, such as for perforating and setting plugs. Such procedures sometimes use a series of alternating perforating guns and plugs to separate completion zones or stages. Autonomous deployment of perforating guns and plugs while pumping the stimulation or fracture treatments may facilitate making perforations and previous zone isolation steps while substantially continuously pumping the stimulation treatments to each subsequent zone without shutting off the pumping other than very brief intermissions. Such processes are known within parts of the industry as the “just-in-time” perforating process. The just-in-time perforating process represents a highly efficient method in that a fracturing fluid may be run into the wellbore with a perforating gun in the hole. As soon as the perfs are shot and fractures are formed, sealing devices are dropped. When the sealing devices seat on the perforations, a gun is shot at the next zone. These steps are repeated until all guns are spent. A new plug 140 is set and the process begins again. This “just-in-time” perforating process reduces flush volumes and offers the ability to manage “screen-outs” along the zones. However, it does require that numerous plugs are then drilled out while exposing the freshly created and fractured zones to the drillout fluids and operation pressures, potentially adversely affecting the completion.
However, need exists for still further improved wellbore perforation sealing technology and/or improved methods to effect a more reliable and effective stimulation fluid diversion system. The art especially needs such reliability improvements that can be economically implemented and provide improved operational reliability. The technology disclosed below addresses one or more of these needs.